Hydrocarbon-producing wells often are stimulated by hydraulic fracturing operations, wherein a fracturing fluid may be introduced into a portion of a subterranean formation penetrated by a wellbore at a hydraulic pressure sufficient to create or enhance at least one fracture therein. Stimulating or treating the wellbore in such ways increases hydrocarbon production from the well. The fracturing equipment may be included in a completion assembly used in the overall production process. Alternatively the fracturing equipment may be removably placed in the wellbore during and/or after completion operations.
In some wells, it may be desirable to individually and selectively create multiple fractures along a wellbore at a distance apart from each other, creating multiple “pay zones.” The multiple fractures should have adequate conductivity, so that the greatest possible quantity of hydrocarbons in an oil and gas reservoir can be drained/produced into the wellbore. When stimulating a formation from a wellbore, or completing the wellbore, especially those wellbores that are highly deviated or horizontal, it may be advantageous to create multiple pay zones. Such multiple pay zones may be achieved by utilizing a variety of tools comprising a movable fracturing tool with perforating and fracturing capabilities, or with actuatable sleeve assemblies, also referred to as sleeves or casing windows, disposed in a downhole tubular.
A typical formation stimulation process might involve hydraulic fracturing of the formation and placement of a proppant in those fractures. Typically, the fracturing fluid and proppant are mixed in containers at the surface of the well site. After the fracturing fluid is mixed, it is pumped down the wellbore where the fluid passes into the formation and induces a fracture in the formation, i.e., fracture initiation. A successful formation stimulation procedure will increase the movement of hydrocarbons from the fractured formation into the wellbore by creating and/or increasing flowpaths into the wellbore.
Conventional formation stimulation procedures are capital intensive. Difficulties often arise in attempting to implement known methods of formation stimulation, for example, relatively high pressures are required to pump the viscous, surface-mixed compositions down the wellbore and into the formation. These pumping requirements necessitate great horsepower and specialized high-rate blending equipment while resulting in excessive wear on pumping equipment. Thus, conventional formation stimulation operations are commonly associated with great cost.
Further, the abrasive and viscous characteristics of fracturing fluid limit the rate at which a fracturing fluid may be pumped downhole. Friction from the high-rate pumping of an abrasive and viscous fracturing fluid may cause downhole wellbore equipment failure, wear, or degradation. Thus, in conventional formation stimulation operations, the rate at which fracturing fluids were pumped to a downhole formation could not be increased beyond the point at which the velocity of the fracturing fluid might result in damage to wellbore equipment. Because an operator would be limited as to the rate at which a fracturing fluid might be pumped downhole, the time necessitated by fracturing operations was greater than it might have been if higher velocity pumping rates were achievable.
Treating pressures may fluctuate, often increase, during the formation stimulation process, whereupon the operator must prematurely terminate the treatment or risk serious problems such as ruptures of surface equipment, wellbore casing, and tubulars. Treating pressures beyond the acceptable range may occur during the formation stimulation process in the event of a premature screenout. Such a screenout occurs where the rate of stimulation fluid leak-off into the formation exceeds the rate at which fluid is being pumped down the wellbore, resulting in the proppant compacting within the fracture. The problems associated with a premature screenout are discussed in U.S. Pat. No. 5,595,245., which is incorporated herein by reference.
Where a premature screenout is detected during a formation stimulation operation, the operator may attempt to alter the density, quantity, or concentration of the proppant laden fluid in an effort to prevent the occurrence of such screenout. However, in conventional formation stimulation operations, alterations to the composition of the fluid made at the surface will not be realized downhole for a significant period of time; thus, such alterations to the composition of the fluid may not be effective in avoiding a screenout.
Further, the volume of fracturing fluid necessitated in a conventional fracturing operation can be very high, thus increasing the substantial costs associated with such processes. In a conventional formation stimulation process, the fracturing fluid is mixed at the surface and pumped down the wellbore, eventually reaching the formation. Thus, the entire flowpath between the surface mixing chamber and the formation must be filled with the fracturing fluid. In deep wellbore embodiments, for example, a wellbore 12,000 feet or more in depth, this means that the entire column must be filled and maintained with fracturing fluid throughout the fracturing operation. The high cost of fracturing fluids paired with the necessary volume of fracturing fluid underscores the capital intensive nature of conventional formation stimulation processes.
Presently, another challenge in treating deep, high volume wellbores is dealing with the volume of fluid required to flush these treatments. A conventional approach would be to run smaller tubulars (e.g., coiled tubing or jointed pipe) into the well, isolating the larger strings (e.g., casing) from the treatment. While this eliminates the need for large pre-flush and flush volumes, it can also pose a significant cost to the customer. With current pinpoint technology, the only way to eliminate the large annular flush volumes is to pump proppant laden fluid down the coiled tubing/jointed pipe. In some processes, a hydrajetting tool on the end of the coiled tubing/jointed pipe remains as the only exit point for the slurry. This limits both the rate, due to friction, and the total mass of proppant which can be pumped due to jet erosion. Thus, a need exists for a wellbore servicing method and apparatus which will allow for high pumping rates while providing the operator with real-time control of the character of a formation stimulation fluid. It is further desirable that such a method and apparatus might have the effect of lessening the amount of capital currently associated with formation stimulation procedures.